Classification: Confidential Status: Draft
Financial highlights – 1Q 2008
Eldar Sætre Chief Financial Officer 2
Solid production in strong markets
• Good financial results • Production on track • Encouraging exploration • Building international growth
Tordis sub sea separation facility 3
Good financial results
Net income up 61%
Net income • Oil price up 42% in NOK Net operating • Gas price up 16% income • Lifting down 3%, equity production up 8% 51.4 Higher net financial income
NOK bn •
34.5
16.0 9.9
1Q 2007 1Q 2008 4
Net income overview
Financial Operating items Taxes income 3.9 (39.3) 51.4 NOK bn
Net income 16.0 5
Production on track Oil Gas
2 0481 1 8891 1 900 824 707
1 182 1 224 1 000 boepd equity production 1 000 boepd equity
1Q 2007 1Q 2008 2008 guidance
1) Average PSA effect is 159 000 boepd in 1Q 2008 compared to 79 000 boepd in 1Q 2007. 6
Production unit cost NOK per boe
• Impact from merger- and restructuring costs 44.1 41.4 41.9 • Injection gas cost NOK 2.6 per boe2
33.2 31.2 31.6
Restructuing costs Injection gas purchase Production unit cost
2007 Entitlement 2007 Equity 1Q 2008 Equity 1
1) 12 month average Production unit cost. 2) Average for the 12 month period ended 31 March 2008. 7
Key deliveries
NCS North America
New leases in Gulf of Mexico New projects on stream: New leases in Alaska Volve Sale of Gulf of Mexico shelf assets Gulltopp Gamma Main Statfjord
Plan for Development and Operation delivered: Yttergryta Russia Morvin Establishment of Shtokman Development Company
Brazil Azerbaijan
Acquisition of Peregrino ACG III (Deep Water Gunashli) on stream
West Africa
Mondo field on stream 8
Encouraging exploration results
NCS Gulf of Mexico Gamma (StatoilHydro) Big Foot Sidetrack (Chevron) Marulk (ENI) Big Foot North (Chevron) M-structure (StatoilHydro) Green Bay (Anadarko) Obesum (StatoilHydro) Hal (ExxonMobil) Natalia (StatoilHydro) St Malo 3 (Chevron) Draupne (NOIL) St Malo 4 (Chevron) Hazel Theta Cook (StatoilHydro) Julia 2 (ExxonMobil) Afrodite (ENI) Sturgis North (Chevron) 14 Alve/Tilje (StatoilHydro) Jack 3 (Chevron) Delta S2 (StatoilHydro) Exploration extension C-Øst (StatoilHydro) 1 Gimle exploration extension (StatoilHydro) Tornerose appraisal (StatoilHydro) North Africa Trane (ConocoPhillips) Hassi Mounia TMS-1 (StatoilHydro) 8 NC 186 V-1 (Repsol) 9 NC 186 X1 (Repsol) NC 186 J5 (Repsol) UK West Africa NC 186 P1 (Repsol) 7 NC 186 Y-1 (Repsol) Amos (Hess) Bl1506 Sangos 1 (ENI) NC 186 Z1 (Repsol) BL 15 Clochas (ExxonMobil) HM TNK W1 (StatoilHydro) Bl 15 Mavacola (ExxonMobil) Bl 31 Palas (BP) Bl 31 Astraea 3 (BP) Under evaluation Bl 31 Elara 1 (BP) Bl 31 Leda 1 (BP) Discovery Ongoing 9
Net operating income - E&P Norway
• Oil price up 40% in NOK • Gas transfer price up 12% • Lifting down 1%, production up 5% – Gas lifting up 14% 42.2 – Oil lifting down 11%
31.0 NOK bn
1Q 2007 1Q 2008 10
Net operating income - International E&P
• Oil price up 51% in NOK • Lifting down 11%, equity production up 21% • Gain of NOK 0.8 billion from sales of assets 4.3 • Exploration expenses up NOK 2.5 billion 3.1 NOK bn
1Q 2007 1Q 2008 11
Net operating income – Natural gas
• Natural gas price up 16% • Transfer price up 12%1 • Natural gas sales up 18% • Positive change in fair value of 1.9 derivatives NOK bn
0.7
1Q 2007 1Q 2008
1) A revised price formula between E&P Norway and Natural Gas was implemented in the first quarter of 2008. 12
Net operating income - Manufacturing and Marketing
• Lower trading result • Reduced refining margins • Negative currency effects
1.4
1.0 NOK bn NOK
1Q 2007 1Q 2008 13
Net operating income by business area
Items Items impacting impacting net Adjusted net net Adjusted net operating operating operating operating NOK billions 1Q 2008 income income 1Q 2007 income income
E&P Norw ay 42.2 0.2 42.4 31.0 -2.3 28.7 International E&P 4.3 2.0 6.3 3.1 0.0 3.1 Natural Gas 1.9 1.0 2.9 0.7 2.1 2.8 Manufacturing & Marketing 1.0 -0.7 0.3 1.4 0.9 2.3 Other 0.8 -0.9 -0.1 -0.5 0.0 -0.5 Eliminations 1.3 -1.3 0.0 -1.2 1.2 0.0
Net operating income 51.4 0.4 51.8 34.5 1.9 36.4 14
Outlook 2Q 2008
• Planned maintenance schedule to affect production by approximately 55 000 boe per day in 2Q 20081 • Planned maintenance stop at Snøhvit • Seasonal lower gas off-take • Continued high exploration activity
1) The NCS effect of planned maintenance includes liquids only. 15
Guiding
2008 • Equity production (mill boepd) 1.9 • Capex (NOK bn) ~75 1 • Exploration activity (NOK bn) ~18 1
2012 • Equity production (mill boepd) 2.2 • Production cost (NOK/ boe 2008 - 2012) 33 - 36 1, 2
1) Based on NOK 6/USD 2) Production cost range during the period 2008-2012, based on equity volumes and excluding gas purchase 16
Supplementary information Page 17 Items impacting income statement 19 Segment taxes 20 Net financial items 21 Net debt to capital employed 22 Simplified cash flow 23 ROACE 24 Key figures StatoilHydro group 26 Exploration StatoilHydro group 27 E&P Norway 29 E&P Norway production 31 International E&P 33 International E&P production 34 Natural Gas 36 Manufacturing & Marketing 40 Sensitivities 41 Reconciliation ROACE 42 Normalised production cost per boe 43 Reconciliation net debt and capital employed 44 Forward-looking statements 45 End notes 17
Items impacting income statement
1Q 2008 1Q 2007 NOK billions Before tax After tax Before tax After tax
Impairment (2.5) (2.5) 0.0 0.0 Derivatives 0.8 0.4 (3.0) (1.4) Over (+) /underlift (-) (1.9) (0.7) 2.1 0.7 Other 3.2 2.8 (1.0) (0.7) Impact on net income (0.4) 0.0 (1.9) (1.4) 18
Items impacting income statement
1Q 2008 1Q 2007 NOK billions Before tax After tax Before tax After tax
Impairment (2.5) (2.5) - - INT (exploration expenses) (2.1) (2.1) - - NG (DD&A) (0.4) (0.4) - -
Derivatives IAS 39 0.8 0.4 (3.0) (1.4) INT - - (0.4) (0.2) EPN 1.0 0.2 0.6 0.1 NG (0.6) (0.1) (2.2) (0.5) M&M 0.4 0.3 (1.1) (0.8)
Underlift (-) /Overlift (+) (1.9) (0.7) 2.1 0.7 EPN (1.2) (0.3) 1.7 0.4 INT (0.7) (0.4) 0.4 0.2
Other 3.2 2.7 (1.0) (0.7) Sale of a subsidiary (Other) 0.9 0.9 - - Operational storage (M&M) 0.3 0.2 0.2 0.1 Sales of assets (INT) 0.8 0.8 - - Eliminations 1.2 0.8 (1.2) (0.8)
Net impact operating income (0.4) 0.0 (1.9) (1.4) 19
Segment taxes
NOK billion 1Q 2008 1Q 2007 Exploration and Production Norway 31.8 23.4 International Exploration and Production 3.4 1.5 Natural Gas 1.3 0.5 Manufactoring and Marketing 0.3 0.6 Eliminations 0.4 (0.5) Tax on financial items and other tax adjustments 2.1 0.3 Total 39.3 25.7 20
Net financial items
Currency gain on long-term Financial Net financial debt expenses items 1Q 2008 Currency gain on liquidity management and other 1.0 Currency 1.7
1.0
NOK bn 3.9 Interest and Net financial other financial 0.7 items 1Q 2007 items (0.1)
1.2 21
Net debt to capital employed
Net debt Net debt to capital employed1
25.5
** ** 12% 24%
2 2 2.1 1% % NOK bn
(12)% (21.1)
2007 1Q 2008 2007 1Q 2008
1) Debt to capital employed ratio = Net interest-bearing debt/capital employed 2) Adjusted for increase in cash for tax payment 22
Simplified cash flow
Depreciations Change in and non cash working Change in items capital non-current (2.7) items Cash flows 11.6 Taxes paid investing (4.8) activities Income (2.2) (Net) before tax
(11.2) Repayment Change in of LT Net ST borrowings borrowings liquid assets = 45.1 (2.0) 1.0
NOK bn Current 55.3 fin. inv. =30.4
Cash =14.7 23
ROACE 22.5% in 1 Q 2008
StatoilHydro 1 Peer group
0% 10% 20% 30%
1) Peer group includes (listed in alphabetical order): Anadarko, BG, BP, ChevronTexaco, CNQ, ConocoPhillips, Devon, Encana, Eni,ExxonMobil, Lukoil, Occidental, Petrobras, Repsol YPF, Shell, Total 24
StatoilHydro group Net operating income changes 4Q 2007– 1Q 2008
1.5 2.1 1.6 3.7 2.0 9.7
51.4
30.8
4Q 2007 E&P Norway International Natural Gas Manufacturing Other Eliminations 1Q 2008 E&P & Marketing 25
StatoilHydro group Net operating income changes 1Q 2007– 1Q 2008
2.5 1.2 (0.4) 1.3 1.1 11.2
51.4
34.5
1Q 2007 E&P Norway International Natural Gas Manufacturing Other Eliminations 1Q 2008 E&P & Marketing 26
Exploration StatoilHydro group
NOK bn. 1Q 2008 1Q 2007 Exploration expenditure 3.9 2.7 Exploration expenditure (activity) 2.2 0.4 Expensed, previously capitalised exploration expenditure -1.9 -1.1 Capitalised share of current period’s exploration activity 4.2 2.0 Exploration expenses NOK bn. 1Q 2008 1Q 2007 Exploration expenses 0.6 0.8 Exploration expenses - Norway 3.6 1.1 Exploration expenses - International
Exploration 2007 YTD Exploration activity 3.9
2.7 2.2 2.1 2.1 (1.9) 3.6 International E&P 1.6 NOK bn E&P Norway NOK bn 1.8 1.2 1.8 Activity Capitalised From prev Expenses 0.6 1Q 2007 1Q 2008 years 27
E&P Norway Net operating income changes 4Q 2007 – 1Q 2008
0.6 (0.1) 42.2 7.0 1.0 (1.8) 2.1 0.9 32.6 NOK bn
4Q 2007 Price Volume Other income Exploration Operating DA&I Sales and 1Q 2008 expenses admin. 28
E&P Norway Net operating income changes 1Q 2007 – 1Q 2008
(1,2) 0.4 0.2 (0.2) (0.3) 0.0 42.2 12.2
31.0 NOK bnNOK
1Q 2007 Price Volume Other income Exploration Operating DA&I Sales and 1Q 2008 expenses admin. 29 StatoilHydro production per field 1Q 2008 StatoilHydro - operated
StatoilHydro-operated StatoilHydro share Produced volumes 1000 boed Oil Gas Total Brage 32.70% 7.8 1.3 9.1 Fram 45.00% 24.0 2.1 26.1 Gimle 65.13% 7.0 0.0 7.0 Glitne 58.90% 5.9 0.0 5.9 Grane 38.00% 66.0 1.9 67.9 Gullfaks 70.00% 115.0 58.7 173.6 Heidrun 12.41% 12.2 2.7 14.9 Heimdal *5 0.1 0.8 1.0 Huldra 19.88% 0.8 3.9 4.7 Kristin 55.30% 67.2 42.0 109.2 Kvitebjørn 58.55% 20.9 35.5 56.4 1. StatoilHydro’s share of the reservoir and production Mikkel 43.97% 5.7 5.9 11.6 at Heimdal is equal to 29.87%. The ownershare of Njord 20.00% 4.4 7.8 12.2 the topside facilities is equal to 39.44% Norne *6 35.3 3.1 38.4 2. Norne 39.10%, Urd 63.95% Oseberg *2 80.8 45.7 126.5 Sleipner *4 36.4 135.2 171.6 3. Oseberg 49.3%, Tune 50.0% Snorre *3 53.7 1.9 55.6 4. Sleipner Vest 58.35%, Sleipner Øst 59.60%, Snøhvit 33.53% 2.4 9.7 12.1 Gungne 62.00% Statfjord * 1 70.6 28.3 98.9 5. StatoilHydro’s share at Snorre is 33.3169%. Tordis 41.50% 15.3 0.1 15.3 Hovever there is an ongoing make-up period at Troll Gass 30.58% 8.0 202.0 210.0 Snorre where the lifting share for oil for the moment Troll Olje 30.58% 47.1 0.0 47.1 is 33.7876%. The make-up period started may 1st Vale 28.85% 1.1 0.9 1.9 2006, and lasts until April 30th 2008 for oil. The lifting share of gas is expected to be different from Veslefrikk 18.00% 2.6 0.0 2.7 the owner share for several years to come Vigdis 41.50% 27.8 2.1 29.9 Visund 53.20% 19.6 12.1 31.8 6. Statfjord unit 44.34%, Statfjord Nord 21.88%, Statfjord Øst 31.69%, Sygna 30.71% Volve 59.60% 5.5 0.0 5.5 Åsgard 34.57% 58.3 63.0 121.3 Total StatoilHydro-operated 802 667 1468 30
StatoilHydro production per field 1Q 2008 Partner - operated
Partner-operated StatoilHydro share Produced volumes 1000 boed Oil Gas Total Ekofisk 7.60% 22.8 4.4 27.2 Enoch 11.78% 0.9 0.0 0.9 Murchison 11.52% 0.4 0.0 0.4 Ormen Lange 28.91% 4.0 45.4 49.4 Ringhorne Øst 14.82% 4.8 0.1 4.9 Sigyn 60.00% 10.0 5.7 15.7 Skirne 10.00% 0.4 2.1 2.6 Total partner-operated 43 58 101 Total production 845 724 1569 31
International E&P Net operating income changes 4Q 2007 – 1Q 2008
2.4
0.7 (1.2) 0.7 (0.6) 4.3
NOK bn NOK 2.2
4Q 2007 Price Volume Depreciation Exploration Other 1Q 2008 32
International E&P Net operating income changes 1Q 2007 – 1Q 2008
(0.9) (0.1)
3.5 (2.5) 1.2
4.3
NOK bn 3.1
1Q 2007 Price Volume Depreciation Exploration Other 1Q 2008 33
International E&P equity production per field
E&P International Produced equity volumes - StatoilHydro 1000 boepd StatoilHydro share Oil Gas Total Alba 17.00% 6.8 6.8 Caledonia 21.32% 0.0 0.0 Jupiter 30.00% 0.8 0.8 Schiehallion 5.88% 4.1 0.1 4.2 Lufeng 75.00% 1.4 1.4 Azeri Chiraq (ACG EOP) 8.56% 63.0 63.0 Shah Deniz 25.50% 10.4 30.8 41.2 Petrocedeño* 9.67% 16.2 16.2 Girassol/Jasmin 23.33% 40.5 40.5 Kizomba A 13.33% 31.2 31.2 Kizomba B 13.33% 33.6 33.6 Xikomba 13.33% 1.8 1.8 Dalia 23.33% 59.0 59.0 Rosa 23.33% 23.7 23.7 In Salah 31.85% 48.5 48.5 In Amenas 50.00% 26.5 26.5 Marimba 13.33% 4.7 4.7 Kharyaga 40.00% 7.8 7.8 Hibernia 5.00% 6.6 6.6 Terra Nova 15.00% 17.0 17.0 Murzuk 8.00% 7.3 7.3 Marbruk 25.00% 4.8 4.8 Lorien 30.00% 1.3 0.2 1.6 Front Runner 25.00% 1.0 1.0 Spiderman Gas 18.33% 0.0 5.6 5.6 Q Gas 50.00% 0.0 7.9 7.9 San Jacinto Gas 26.67% 0.0 5.2 5.2 Zia 35.00% 0.3 0.0 0.4 Seventeen hands 25.00% 0.0 0.6 0.6 Mondo 13.33% 10.1 10.1 Total 379 100 479 34
Natural gas Net operating income changes 4Q 2007 – 1Q 2008
2.5 (6.1)
1.7 0.5
1.9 3.2 0.9
NOK bn 1.0
(1.8)
4Q 2007 Sales price Purchase Sales Purchase Opex IAS 39 Other 1Q 2008 Price volume volum e 35
Natural gas Net operating income changes 1Q 2007 – 1Q 2008
3.8 (3.4) (4.0) 3.7 NOK bn (0.1)
1.5 1.9 (0.3) 0.7
1Q 2007 Sales price Purchase Sales Purchase Opex IAS 39 Other 1Q 2008 price volum e volum e 36
Manufacturing & Marketing Net operating income changes 4Q 2007 – 1Q 2008
0.7 1.0
(0.6) 1.3 (0.2) NOK bn (0.2)
4Q 2007 Oil Sales Manufacturing Marketing Other 1Q 2008 37
Manufacturing & Marketing Net operating income changes 1Q 2007 – 1Q 2008
0.2 (0.5)
(0.1) (0.1)
1.4
1.0 NOK bn
1Q 2007 Oil Sales Manufacturing Marketing Other 1Q 2008 38
Manufacturing & Marketing Income statement
NOK bn M&M - distribution of Net operating income 1Q 2008 1Q 2007 Oil sales & trading 0.2 0.0 Manufacturing 0.5 1.0 Marketing 0.3 0.4 Other -0.1 0.0 Total 1.0 1.4
M&M - operational data 1Q 2008 1Q 2007 FCC margin (USD/bbl) 5.6 5.4 Contract price methanol (EUR/t) 490 420 39
Manufacturing & Marketing Margins and prices
FCC NWE refining margins Methanol contract price
USD/bbl EUR/ton 2008 2007 550
14 500 450 12 400 10 350 8 300
6 250 200 4 150 2 100 0 50 JFMAMJJASOND JFMAMJ J ASOND 40
Sensitivities, effect of changes in parameters
Net income effect
NOK bn Net operating income 1 Oil price + USD 1/bbl effect 3
1 Gas price + NOK 0.1/scm 4
A ) Exchange rate + NOK 0.5/USD (P&L effect excl 4 finance) 13
B ) Exchange rate + NOK 0.5/USD (P&L effect from (2) long term debt) (4)
A + B ) Exchange rate + NOK 0.5/USD (total P&L 2 effect) 9
The sensitivity analysis is based on planning assumptions and shows the impact on 2008 41
Reconciliation ROACE 42
Normalised production cost per boe 43
Reconciliation net debt and capital employed 44
Forward looking statements
This Operating and Financial Review contains certain forward-looking statements that involve risks and uncertainties. In some cases, we use words such as "believe", "intend", "expect", "anticipate", "plan", "target" and similar expressions to identify forward-looking statements. All statements other than statements of historical fact, including, among others, statements such as those regarding: plans for future development and operation of projects; reserve information; expected exploration and development activities; expected start-up dates for projects and expected production and capacity of projects; expected operatorships and expected dates of operatorship transitions; the completion of acquisitions; and the obtaining of regulatory and contractual approvals are forward-looking statements. These forward-looking statements reflect current views with respect to future events and are, by their nature, subject to significant risks and uncertainties because they relate to events and depend on circumstances that will occur in the future. There are a number of factors that could cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements, including levels of industry product supply, demand and pricing; price and availability of alternative fuels; currency exchange rates; political and economic policies of Norway and other oil-producing countries; general economic conditions; political stability and economic growth in relevant areas of the world; global political events and actions, including war, terrorism and sanctions; the timing of bringing new fields on stream; material differences from reserves estimates; inability to find and develop reserves; adverse changes in tax regimes; development and use of new technology; geological or technical difficulties; the actions of competitors; the actions of field partners; the actions of governments; relevant governmental approvals; industrial actions by workers; prolonged adverse weather conditions; natural disasters and other changes to business conditions. Additional information, including information on factors which may affect StatoilHydro's business, is contained in StatoilHydro's 2007 Annual Report on Form 20-F filed with the US Securities and Exchange Commission, which can be found on StatoilHydro's web site at www.StatoilHydro.com. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot assure you that our future results, level of activity, performance or achievements will meet these expectations. Moreover, neither we nor any other person assumes responsibility for the accuracy and completeness of the forward-looking statements. Unless we are required by law to update these statements, we will not necessarily update any of these statements after the date of this review, either to make them conform to actual results or changes in our expectations. 45
End notes
1. After-tax return on average capital employed for the last 12 months is calculated as net income after-tax net financial items adjusted for accretion expenses, divided by the average of opening and closing balances of net interest-bearing debt, shareholders' equity and minority interest. See table under report section Return on average capital employed after tax for a reconciliation of the numerator. See table under report section Net debt to capital employed ratio for a reconciliation of capital employed. StatoilHydro's first quarter 2008 interim consolidated financial statements have been prepared in accordance with IFRS. Comparative financial statements for previous periods presented have also been prepared in accordance with IFRS.
2. For a definition of non-GAAP financial measures and use of ROACE, see report section Use and reconciliation of non-GAAP measures.
3. The group's average oil price is a volume-weighted average of the segment prices of oil and natural gas liquids (NGL), including a margin for oil sales, trading and supply.
4. FCC margin is an in-house calculated refinery margin benchmark intended to represent a 'typical' upgraded refinery with an FCC (fluid catalytic cracking) unit located in the Rotterdam area based on Brent crude.
5. A total of 13 mboe per day in the first quarter of 2008 represents our share of production in an associated company. These volumes have been included in the production figure, but excluded when computing the over/underlift position. The computed over/underlift position is therefore based on the difference between produced volumes excluding our share of production in an associated company and lifted volumes.
6. Oil volumes include condensate and NGL, exclusive of royalty oil.
7. Lifting of oil corresponds to sales of oil for E&P Norway and International E&P. Deviations from share of total lifted volumes from the field compared to the share in the field production are due to periodic over- or underliftings.
8. The production cost is calculated by dividing operational costs related to the production of oil and natural gas by the total production of oil and natural gas. For a specification of normalising assumptions, see end note 9. For normalisation of production cost, see table under report section Normalised production cost.
9. By normalisation it is assumed that production costs in E&P Norway are incurred in NOK. Only costs incurred in International E&P are normalised at a USDNOK exchange rate of 6.00. For purposes of measuring StatoilHydro's performance against the 2008 guidance for normalised production cost, a USDNOK exchange rate of 6.00 is used.
10. Equity volumes represent produced volumes under a Production Sharing Agreement (PSA) contract that correspond to StatoilHydro's ownership percentage in a particular field. Entitlement volumes, on the other hand, represent the StatoilHydro share of the volumes distributed to the partners in the field, which are subject to deductions for, among other things, royalty and the host government's share of profit oil. Under the terms of a PSA, the amount of profit oil deducted from equity volumes will normally increase with the cumulative return on investment to the partners and/or production from the licence. As a consequence, the gap between entitlement and equity volumes will likely increase in times of high oil prices. The distinction between equity and entitlement is relevant to most PSA regimes, whereas it is not applicable in most concessionary regimes such as those in Norway, the UK, Canada and Brazil.
11. Net interest-bearing debt is long-term interest-bearing debt and short-term interest-bearing debt reduced by cash, cash equivalents and short-term investments. In the first and third quarter, net interest-bearing debt is normalised by excluding 50% of the cash build-up related to tax payments due in the beginning of April and October each year. 46
Investor relations in StatoilHydro
Lars Troen Sørensen senior vice president [email protected] +47 51 99 77 90 Morten Sven Johannessen IR officer [email protected]+47 51 99 42 01 Herlaug Louise Barkli IR officer [email protected] +47 51 99 21 38 Anne Lene Gullen Bråten IR officer [email protected] +47 99 54 53 40 Lars Valdresbråten IR officer [email protected] +47 40 28 17 89 Lill Gundersen IR assistant [email protected] +47 51 99 86 25
Investor relations in the USA Geir Bjørnstad vice president [email protected] +1 203 978 6950 Ole Johan Gillebo IR analyst [email protected] +1 203 978 6986 Peter Eghoff IR trainee [email protected] +1 203 978 6900
For more information: www.statoilhydro.com